Emerging continuous gas plays in the Cooper Basin, South Australia

2012 ◽  
Vol 52 (2) ◽  
pp. 671
Author(s):  
Sandra Menpes ◽  
Tony Hill
Keyword(s):  
Shale Gas ◽  
South Australia ◽  
Flood Plain ◽  
Source Rocks ◽  
Early Permian ◽  
Gas Shale ◽  
Freshwater Lakes ◽  
Gas Desorption ◽  
Wet Gas ◽  
Cooper Basin

Recent off-structure drilling in the Nappamerri Trough has confirmed the presence of gas saturation through most of the Permian succession, including the Roseneath and Murteree shales. Basin-centred gas, shale gas and deep CSG plays in the Cooper Basin are now the focus of an escalating drilling and evaluation campaign. The Permian succession in the Nappamerri Trough is up to 1,000 m thick, comprising very thermally mature, gas-prone source rocks with interbedded sands—ideal for the creation of a basin-centred gas accumulation. Excluding the Murteree and Roseneath shales, the succession comprises up to 45% carbonaceous and silty shales and thin coals deposited in flood plain, lacustrine and coal swamp environments. The Early Permian Murteree and Roseneath shales are thick, generally flat lying, and laterally extensive, comprising siltstones and mudstones deposited in large and relatively deep freshwater lakes. Total organic carbon values average 3.9% in the Roseneath Shale and 2.4% in the Murteree Shale. The shales lie in the wet gas window (0.95–1.7% Ro) or dry gas window (>1.7% Ro) over much of the Cooper Basin. Thick Permian coals in the deepest parts of the Patchawarra Trough and over the Moomba high on the margin of the Nappamerri Trough are targets for deep CSG. Gas desorption analysis of a thick Patchawarra coal seam returned excellent total raw gas results averaging 21.2 scc/g (680 scf/ton) across 10 m. Scanning electron microscopy has shown that the coals contain significant microporosity.

Shale gas prospectivity in South Australia

2011 ◽  
Vol 51 (2) ◽  
pp. 718
Author(s):  
Anthony Hill ◽  
Sandra Menpes ◽  
Guillaume Backè ◽  
Hani Khair ◽  
Arezoo Siasitorbaty
Keyword(s):  
Shale Gas ◽  
South Australia ◽  
Source Rocks ◽  
Type Ii ◽  
Gas Generation ◽  
Eastern Australia ◽  
Gas Potential ◽  
Gas Bearing ◽  
Excellent Source ◽  
Cooper Basin

Potential shale gas bearing basins in SA are primarily dominated by thermogenic play types and span the Neoproterozoic to Cretaceous. Whilst companies have only recently commenced exploring for shale gas in the Permian Cooper Basin, strong gas shows have been routinely observed and recorded since exploration commenced in the basin in 1959. The regionally extensive Roseneath and Murteree shales represent the primary exploration focus and reach maximum thicknesses of 103 m and 86 m respectively with TOC values up to 9%. These shales are in the gas window in large parts of the basin, particularly in the Patchawarra and Nappamerri troughs. Outside the Cooper Basin, thick shale sequences in the Crayfish Subgroup of the Otway Basin, in particular the Upper and Lower Sawpit shales and to a lesser extent the Laira Formation, have good shale gas potential in the deeper portions of the basin. TOC averages up to 3% are recorded in these shales in the Penola Trough; maturities in the range of 1.3–1.5% have been modelled. Thick Permian marine shales of the Arckaringa Basin have excellent source rock characteristics, with TOC’s ranging 4.1–7.4% and averaging 5.2% over an interval exceeding 150 m in the Phillipson Trough; however, these Type II source rocks are not sufficiently mature for gas generation anywhere in the Arckaringa Basin. Shale gas has the potential to rival CSM in eastern Australia; its potential is now being explored in SA.

Monitoring shale gas resources in the Cooper Basin using magnetotellurics

Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. A13-A16 ◽  
Author(s):  
Nigel Rees ◽  
Simon Carter ◽  
Graham Heinson ◽  
Lars Krieger
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
South Australia ◽  
Depth Range ◽  
Bulk Conductivity ◽  
Gas Reservoirs ◽  
Horizontal Fracture ◽  
Fluid Permeability ◽  
Fracturing Fluids ◽  
Cooper Basin

The magnetotelluric (MT) method is introduced as a geophysical tool to monitor hydraulic fracturing of shale gas reservoirs and to help constrain how injected fluids propagate. The MT method measures the electrical resistivity of earth, which is altered by the injection of fracturing fluids. The degree to which these changes are measurable at the surface is determined by several factors, such as the conductivity and quantity of the fluid injected, the depth of the target interval, the existing pore fluid salinity, and a range of formation properties, such as porosity and permeability. From an MT monitoring survey of a shale gas hydraulic fracture in the Cooper Basin, South Australia, we have found temporal and spatial changes in MT responses above measurement error. Smooth inversions are used to compare the resistivity structure before and during hydraulic fracturing, with results showing increases in bulk conductivity of 20%–40% at a depth range coinciding with the horizontal fracture. Comparisons with microseismic data lead to the conclusion that these increases in bulk conductivity are caused by a combination of the injected fluid permeability and an increase in wider scale in situ fluid permeability.

SEISMIC AVO STUDIES ASSIST IN THE MAPPING OF A PERMIAN GAS SAND AT KERNA FIELD, COOPER BASIN

1991 ◽  
Vol 31 (1) ◽  
pp. 244
Author(s):  
J. Pinchin ◽  
A.B. Mitchell
Keyword(s):  
South Australia ◽  
Flood Plain ◽  
Seismic Facies ◽  
Gas Field ◽  
Seismic Modelling ◽  
Coal Beds ◽  
South Central ◽  
Amplitude Versus Offset ◽  
Modelling Studies ◽  
Cooper Basin

Kerna is a gas field within the south-central part of the Cooper Basin, 12 km southwest of the Dullingari Field and adjacent to the border of South Australia and Queensland. The trap is a domal anticline containing gas structurally trapped within the Early Permian Patchawarra Formation. The overlying Permian Epsilon Formation, above intervening shale, also contains gas, which may be stratigraphically trapped or restricted by permeability barriers around the southern and western flanks of the field.Seismic reflection amplitudes can be used to map the extent of the Epsilon gas sand. Seismic modelling studies show that the gas sand displays an amplitude-versus-offset (AVO) effect which distinguishes the gas sand from a wet sand or from a coal reflection at the same stratigraphic level. The spatial distribution of the AVO anomalies, and of the overall seismic stack response, has been mapped across the field. The interpreted 'seismic facies' map shows a meander belt across a coal swamp dominated flood plain. The distribution of AVO anomalies within and around this meander belt shows the likely occurrence of gas-bearing sandstones.This study has implications for other areas of the Cooper Basin where adequate separation between coal beds and gas sands allows the AVO effect of the latter to be observed. These AVO effects can then be used as a direct indicator of gas in stratigraphic and structural traps.

LITHOFACIES STUDY ON THE TOOLACHEE FORMATION, GIDGEALPA-MOOMBA-BIG LAKE AREA, COOPER BASIN, SOUTH AUSTRALIA

1973 ◽  
Vol 13 (1) ◽  
pp. 41
Author(s):  
Roger C. N. Thornton
Keyword(s):  
South Australia ◽  
Flood Plain ◽  
Depositional Environments ◽  
Core Material ◽  
Upper Permian ◽  
Limited Area ◽  
Lake Area ◽  
Opposite Trend ◽  
Flow Gradient ◽  
Cooper Basin

A lithofacies study on the Upper Permian Toolachee Formation has been conducted in the Gidgealpa-Moomba-Big Lake area to determine the suitability of the technique in the reconstruction of depositional environments and palaeogeographic trends throughout the Cooper Basin. The Toolachee Formation is one of the main gas producing intervals in the basin, especially in the area of study, which is approximately 2,000 square kilometres. Thirty-one wells drilled in this region indicate that the formation ranges in thickness from 35 metres to over 115 metres.The Toolachee Formation, taken as a whole, is too thick to show any significant features on a lithofacies map over the limited area of investigation. However, lithofacies maps of three approximately chronostratigraphic subdivisions of the same formation show both vertical and lateral trends. Vertically, the percentage of sandstone decreases from the lowermost subdivision to the uppermost subdivision; coal percentages show the opposite trend; and core material shows fining upwards sequences. Laterally, isopachous thin areas (depositional highs) in most cases correlated with an increase in shale or coal lithologies. Histograms of coal cycles show that the lower and middle parts have similar composite sequences of, from the base upwards, sandstone mixture of sandstone and shale-shalecoal.The depositional model proposed is an aggradational flood-plain which, prior to the commencement of deposition, had been eroded to a peneplain. Sediments were deposited from rivers of gradually declining flow gradient until marsh and lacustrine conditions prevailed for long periods of time. Deposition ceased at the sediplain stage.

DEEP BASIN GAS: A NEW EXPLORATION PARADIGM IN THE NAPPAMERRI TROUGH, COOPER BASIN, SOUTH AUSTRALIA

2001 ◽  
Vol 41 (1) ◽  
pp. 185 ◽  
Author(s):  
R.R. Hillis ◽  
J.G.G. Morton ◽  
D.S. Warner ◽  
R.K. Penney
Keyword(s):  
South Australia ◽  
Source Rocks ◽  
Deep Basin ◽  
Gas Accumulation ◽  
Impermeable Barrier ◽  
Trapped Gas ◽  
Giant Fields ◽  
Rock Section ◽  
Sweet Spots ◽  
Cooper Basin

Deep basin hydrocarbon accumulations have been widely recognised in North America and include the giant fields of Elmworth and Hoadley in the Western Canadian Basin. Deep basin accumulations are unconventional, being located downdip of water-saturated rocks, with no obvious impermeable barrier separating them. Gas accumulations in the Nappamerri Trough, Cooper Basin, exhibit several characteristics consistent with North American deep basin accumulations. Log evaluation suggests thick gas columns and tests have recovered only gas and no water. The resistivity of the entire rock section exceeds 20 Ωm over large intervals, and, as in known deep basin accumulations, the entire rock section may contain gas. Gas in the Nappamerri Trough is located within overpressured compartments which witness the hydraulic isolation necessary for gas saturation outside conventional closure. Furthermore, the Nappamerri Trough, like known deep basin accumulations, has extensive, coal-rich source rocks capable of generating enormous hydrocarbon volumes. The above evidence for a deep basin-type gas accumulation in the Nappamerri Trough is necessarily circumstantial, and the existence of a deep gas accumulation can only be proven unequivocally by drilling wells outside conventional closure.Exploration for deep basin-type accumulations should focus on depositional-structural-diagenetic sweet spots (DSDS), irrespective of conventional closure. This is of particular significance for a potential Nappamerri Trough deep basin accumulation because depositional models suggest that the best net/gross may be in structural lows, inherited from syndepositional lows, that host stacked channel sands within channel belt systems. Limiting exploration to conventionally-trapped gas may preclude intersection with such sweet spots.

Fracture mapping and modelling in shale-gas target in the Cooper Basin, South Australia

2011 ◽  
Vol 51 (1) ◽  
pp. 397 ◽  
Author(s):  
Guillaume Backé ◽  
Hani Abul Khair ◽  
Rosalind King ◽  
Simon Holford
Keyword(s):  
Shale Gas ◽  
Seismic Data ◽  
Oil And Gas ◽  
South Australia ◽  
Horizontal Stress ◽  
Fracture Network ◽  
Low Permeability ◽  
Lake Area ◽  
Stress Regime ◽  
Cooper Basin

The success story of a shale-gas reserve development in the United States is triggering a strong industry focus towards similar plays in Australia. The Cooper Basin (located at the border of South Australia and Queensland) and the Otway Basin (extending both onshore and offshore South Australia and Victoria) could be prime targets to develop shale-gas projects. The Cooper Basin, a late-Carboniferous to mid-Triassic basin, is the largest onshore sedimentary basin producing oil and gas from tight conventional reservoirs with low permeability. Fracture stimulation programs are used extensively to produce the oil and gas. Furthermore, new exploration strategies are now targeting possible commercial gas hosted in low-permeability Permian shale units. To maximise production, the development of shale-gas prospects requires a good understanding of the: 1. structure of the reservoirs; 2. mechanical properties of the stratigraphy; 3. fracture geometry and density; 4. in-situ stress field; and, 5. fracture stimulation strategies. In this study, we use a combination of seismic mapping techniques–including horizon and attribute mapping, and an analysis of wellbore geophysical logs–to best constrain the existing fracture network in the basins. This study is based on the processing and analysis of a 3D seismic cube–the Moomba Big Lake survey–which is located in the southwestern part of the Cooper Basin. This dataset covers an area encompassing both a structurally complex setting in the vicinity of a major fault to the SE of the survey, and an area of more subtle deformation corresponding to the southernmost part of the Nappamerri Trough. Structural fabrics trending ˜NW–SE and NE–SW, which are not visible on the amplitude seismic data, are revealed by the analysis of the seismic attributes–namely a similarity (equivalent to a coherency cube), dip steering and maximum curvature attributes. These orientations are similar to those of natural fractures mapped from borehole images logs, and can therefore be interpreted as imaging natural fractures across the Moomba-Big Lake area. This study is the first of its kind able to detect possible fractures from seismic data in the Cooper Basin. The methodology developed here can offer new insights into the structure of sedimentary basins and provide crucial parameters for the development of tight reservoirs. In parallel, a tentative forward model of the generation of a fracture network following a restoration of the Top Roseneath horizon was carried out. The relatively good correlation between the fracture orientations generated by the model and the fractures mapped from geophysical data shows that fractures in the Moomba-Big Lake area may have formed during either a N–S compressive principal horizontal stress, or an E–W compressive principal horizontal tectonic stress regime. In addition, the orientations of the fracture interpreted through this study are also compatible with a generation under the present day stress regime described in this part of the basin, with an maximal horizontal stress trending E–W.

Lithofacies analysis and sequence stratigraphy of the Roseneath-Epsilon-Murteree gas plays in the Cooper Basin, South Australia

2017 ◽  
Vol 57 (2) ◽  
pp. 749
Author(s):  
Fengtao Guo ◽  
Peter McCabe
Keyword(s):  
South Australia ◽  
Flood Plain ◽  
X Ray Diffraction ◽  
Sedimentary Evolution ◽  
Facies Associations ◽  
Three Stages ◽  
Mouth Bar ◽  
Mouth Bars ◽  
Stacking Patterns ◽  
Cooper Basin

The early–middle Permian Roseneath-Epsilon-Murteree (REM) strata of the Cooper Basin, South Australia, has conventional and unconventional gas plays. To better understand the sedimentary evolution of the strata, eight key cored wells for the REM in the South Australia were selected and more than 1400 m cores have been characterised to study the lithofacies, facies associations and associated stacking patterns. Twelve lithofacies are identified and further categorised into eight facies associations: (1) open lacustrine, (2) lacustrine shoreface, (3) flood plain/interdistributary bay/channel fill, (4) fluvial channel/distributary channel, (5) crevasse channel/splay/natural levee, (6) distributary mouth bar, (7) prodelta, and (8) mire/swamp. Cyclic stacking patterns are distinguished both in cores and well logs. X-ray diffraction analysis indicates the lower and middle parts of the Murteree Shale mainly consist of claystone and are characteristic of deep water sediments. The upper Murteree Shale has a larger percentage of silt and sand, which suggests an overall regressive process. The Epsilon Formation displays three stages of deposition: (1) a lower, thin, upward-coarsening package of beach and lacustrine shoreline deposits with a continued regression from the underlying Murteree Shale; (2) a coaly, middle unit deposited by distributary channels, crevasse splays, mires and delta mouth bars; and (3) an upper unit of cyclic coarsening-upward claystone, siltstone and sandstone, deposited in shoreline environments with fluvial modifications. The Roseneath Shale resulted from transgression after deposition of the upper Epsilon Formation with a relatively rapid rise of lake level marked by transgressive lags. A final coarsening-upward sequence of shoreline deposits indicates an ending phase of regression.

GEOLOGY OF THE DELLA FIELD, A PERSPECTIVE ON THE HISTORY OF THE COOPER BASIN

1984 ◽  
Vol 24 (1) ◽  
pp. 266
Author(s):  
D. I. Gravestock ◽  
J. G. G. Morton
Keyword(s):  
South Australia ◽  
Early Permian ◽  
Channel Migration ◽  
Fault Activity ◽  
Facies Associations ◽  
History Of ◽  
Petrophysical Logs ◽  
Fluvial Sandstone ◽  
Active Channel ◽  
Cooper Basin

The Della Field produces dry gas from stacked fluvial sandstone reservoirs in the Early Permian Patchawarra Formation and Late Permian Toolachee Formation. Localised but severe fault activity and erosion in the late Early Permian have resulted in structural and stratigraphic complexities, particularly on the western flank of the field.A detailed study of lithofacies associations from cores has enabled constraints on the resolution of petrophysical logs to be appreciated. Within these constraints major facies associations are mappable across the field. Active channel migration in the Patchawarra Formation resulted in erosion and hence incomplete preservation of the fluvial sequence, which hinders mapping across the field. In contrast, the successive fluvial cycles of the Toolachee Formation are more completely preserved, enabling intrafield and some interfield correlation and mapping. The contrast is due to changing responses of the fluvial regime to prevailing tectonic conditions.A preliminary fluvial facies model, proposed after the first six Della wells, was upgraded during development drilling, with the result that productive reservoirs were successfully predicted. Integration of all available data provides one perspective on the evolution of the Cooper Basin in South Australia.

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